Integration of systems is per se known. By way of example, the integration of an isomerization process with a disproportionation process around a common compressor is taught in U.S. Patent Publication 2010-0004493. In another example, the preparation of liquid hydrocarbons from a light hydrocarbonaceous feedstock is combined with a process for liquefying natural gas, involving the production of syngas (CO and H2), is taught in U.S. Pat. No. 7,451,618.
Aromatic hydrocarbons, particularly benzene, toluene, and xylenes (collectively, “BTX”) and also ethylbenzene, are important commodity chemicals in the petrochemical industry. Currently, aromatic hydrocarbons are most frequently produced from petroleum-based feedstocks by a variety of processes, including catalytic reforming and catalytic cracking. However, as the world supplies of petroleum feedstocks decrease, there is a growing need to find alternative sources of aromatic hydrocarbons.
One possible alternative source of aromatic hydrocarbons is methane. The present inventors have noted that possible sources of methane include natural gas and biogas. More natural gas is currently being discovered than oil. Likewise, production and collection of biogas, such as from landfill (e.g., “garbage dumps”) is increasing tremendously. However, there are numerous problems associated with transportation of large volumes of such gases. For instance, natural gas recovered along with oil (also known as “associated gas”), particularly at remote places, is generally flared and thus wasted. More efficient use of such gases is critical.
A large majority of the processes currently proposed for converting methane to liquid hydrocarbons involve initial oxidation of methane to synthesis gas, such as U.S. Pat. No. 7,451,618 referenced above.
In U.S. Pat. No. 7,451,618 (EP 1306632), liquid hydrocarbons are produced from a light hydrocarbonaceous feedstock in combination with a process for liquefying natural gas, which liquefaction process comprises converting a light hydrocarbonaceous feedstock into synthesis gas, followed by catalytic conversion of the synthesis gas into liquid hydrocarbons. While this application claims efficiencies associated with integration of two processes (natural gas liquefaction and liquid hydrocarbon synthesis), it is still inherently inefficient for at least two reasons, one being the large pressure differential between the liquefaction effluent stream and the preferred operating pressure for the liquid hydrocarbon synthesis, and another being that production of synthesis gas as an intermediate step in the production of liquid hydrocarbons is capital and energy intensive. Accordingly, a more efficient integration of methane conversion technologies with gas liquefaction would be of value.
A number of other processes have been proposed for directly converting methane to higher hydrocarbons, such as catalytic oxidative coupling of methane to olefins followed by the catalytic conversion of the olefins to liquid hydrocarbons, including aromatic hydrocarbons. See, for example, U.S. Pat. No. 5,336,825. However, oxidative coupling methods suffer from the problem that they involve highly exothermic reactions (and thus are exposed to potentially hazardous methane combustion reactions) and they generate large quantities of environmentally sensitive carbon oxides.
Non-oxidative coupling has also been proposed in numerous patents, typically involving contacting methane with a catalyst comprising a metal supported on a zeolite, such as ZSM-5, at high temperature, such as 600° C. to 1000° C. See, for example, patents cited in the Background section of U.S. Patent Publication 2007/0260098.
Non-oxidative coupling methods include dehydroaromatization. As used herein, the term “dehydroaromatization” means processes comprising non-oxidative coupling reactions wherein methane is converted to aromatic hydrocarbons, such as benzene, toluene, and naphthalene (commonly referred to collectively as “BTN”), along with H2, using a supported metal catalyst. Syngas is not a significant intermediate. Such processes have also been referred to as dehydrocyclization, although the latter can also include (or be confused with) the production of cyclic paraffins. Such prior art dehydroaromatization processes are almost exclusively “once through” (no recycle) and do not address separation of the products.
For instance, in the aforementioned U.S. Patent Publication 2007/0260098, a process is described for converting methane to higher hydrocarbons including aromatic hydrocarbons, the process comprising contacting a feed containing methane with a catalyst useful for dehydroaromatization, conveniently molybdenum, tungsten and/or rhenium or a compound thereof on ZSM-5 or an aluminum oxide, under conditions effective to convert said methane to aromatic hydrocarbons and produce a first effluent stream comprising aromatic hydrocarbons and H2, wherein said first effluent stream comprises at least 5 wt % more aromatic rings than said feed; and reacting at least part of the H2 from said first effluent stream with an oxygen-containing species to produce a second effluent stream having a reduced H2 content compared with said first effluent stream.
Other references pertinent to dehydroaromatization include U.S. Patent Publications 2008/0047872; 2008/0058564; 2007/0249740; 2007/0129587 (now allowed); 2007/0282145; 2008/0021251; 2008/0051617; 2007/0249880; 2007/0260098; 2009/0030253; U.S. Pat. Nos. 7,589,246 and 7,659,437; WO 2009/097067, and WO 2007/123808.
In order for a methane conversion process to be adopted on a commercial scale, most of the gas used in the process needs to be converted to high value products, such as benzene, and/or moderate to high value co-products, such as H2. Without wishing to be bound by theory, based on thermodynamic considerations there is only a limited amount of the methane feed that can be converted to aromatic products, at reasonable (i.e., economically viable) operating conditions. Accordingly, the product stream contains large amounts of unreacted methane as well as H2 and aromatic species. Separation of BTN and light olefin byproducts can be accomplished by methods known per se, however, separation of byproduct H2 from CH4 is difficult, requiring expensive equipment and high energy use.
Recovery of relatively high purity H2 (low CH4 content) for uses such as catalyst regeneration and/or to make syngas for methanol or other product synthesis, and likewise recovery of relatively high purity CH4 (low H2 content) is also needed so that it can be recycled as feed to the reactor. In addition, reactor conversion of methane to aromatic hydrocarbons is depressed by the presence of H2 in the feed.
Accordingly, a more efficient process for separation of H2 and CH4 from each other is highly desired. Heretofore, cryogenic separation of H2 and CH4, although thought to be one of the more effective means of achieving the separation, was very expensive; requiring large capital expense for multiple refrigeration machines with various refrigerants (e.g., C3, C2, and C1) or very large mixed refrigerant systems. Also resultant liquid methane must be reheated back to reactor inlet temperature, which is on the order of 500° C. or higher.
Often rather than chemically converting methane to another material for transportation, it is cooled to low enough temperatures that it liquefies so that it can be transported in liquid form as LNG (Liquefied Natural Gas). With regard to gases taken at the well-head and/or biogases, extensive refrigeration is required to cool to liquefaction temperatures. The final step is pressure reduction to atmospheric pressure with auto-refrigeration and the production of a low pressure gas stream (“boil off gas” or LNG BOG). Depending on the temperature and pressure of the stream prior to the pressure reduction to atmospheric pressure with auto-refrigeration, more or less LNG BOG is produced. If there is an outlet for more LNG BOG then the cryogenic refrigeration operation will be more economically attractive, e.g., if more and/or higher use for LNG BOG can be found the temperature of the refrigeration system(s) can be raised. So, from an efficiency standpoint, when LNG BOG volume is set by the outlet (disposition) for this stream being, by way of example, fuel used by the LNG complex, this will essentially set the required temperature prior to flashing. LNG BOG must also be compressed up to approximately 350 psi for use in gas turbines to run the LNG complex. Furthermore, Jetty BOG is also produced when LNG tankers are filled and the vapor volume is displaced. LNG BOG and Jetty BOG will be referred to collectively herein as “BOG”, unless otherwise specifically noted. BOG tends to be enriched in inerts (predominately N2), and these inerts are practically non-condensables in the natural gas. A more efficient use of BOG is thus highly sought after.
LNG is produced in parts of the world where there are large reserves of natural gas but paradoxically little use for it. The natural gas is thus transported as LNG to locations where it can be used for heating, power generation or industrial use. However, LNG cannot be utilized in the liquid form and therefore it must be converted back to a gas at high pressure for distribution to consumers. To supply vaporized gas at pipeline pressure, a portion of the gas is burned to provide heat which is inefficient in that a portion of the gas is consumed. It would be beneficial if the gasification of LNG could be integrated with one or more other processes.
U.S. Pat. No. 7,019,184 teaches a process in which natural gas is non-oxidatively converted to aromatic liquid and is said to provide integration of the separation of wellhead fluids into associated gas and crude with blending of the aromatic liquid derived from the gas with the crude and/or integration of conversion of byproduct H2 to power with non-oxidative conversion of gas to aromatic liquid. Separation of unreacted methane and recycle of the same back to the reactor is taught.
WO 2010004300 teaches a process for treating offshore natural gas. The process comprises (i) liquefying and fractionating the natural gas to generate a liquefied natural gas stream and a higher hydrocarbon stream, (ii) vapourising at least a portion of said higher hydrocarbon stream, (iii) passing the vapourised higher hydrocarbon stream and steam over a steam reforming catalyst to generate a reformed gas mixture comprising methane, steam, carbon oxides and hydrogen, (iv) passing the reformed gas mixture over a methanation catalyst to generate a methane rich gas, and (v) combining the methane-rich gas with the natural gas prior to the liquefaction step. The process requires first separating the higher hydrocarbon from the methane; then reacting the higher hydrocarbon with steam to make CO and H2; then (with a second catalyst at a second set of reaction conditions) reacting the CO and H2 to produce methane and water.
The present inventors have surprisingly discovered that the process of taking well-head gases to the consumer may be integrated with the production of aromatic hydrocarbons by dehydroaromatization.